Combustion thermal generator and systems and methods for enhanced oil recovery

ABSTRACT

An apparatus for combustion steam generation is provided, which includes a combustion chamber having an inlet end and an outlet end; a manifold at the inlet end configured to introduce a fuel and an oxidizer into the combustion chamber; an outer casing defining a coolant chamber between the outer casing and the combustion chamber; and a plurality of converging coolant inlets for conducting coolant from the coolant chamber into the combustion chamber at or near the outlet end of the combustion chamber. The converging coolant inlets are radially disposed around the combustion chamber and preferably configured to produce a converging-diverging nozzle from the coolant conducted into the combustion chamber. The device may be used in systems and methods for enhanced recovery of subterranean hydrocarbons, by deployment into and operation in a wellbore, where the produced steam and combustion gases are injected into a hydrocarbon formation to enhance hydrocarbon recovery.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application is a divisional of U.S. application Ser. No.13/302,783, filed Nov. 22, 2011, which claims the benefit of U.S.Provisional Application No. 61/415,892, filed Nov. 22, 2010, which areincorporated herein by reference in their entirety.

BACKGROUND

This invention relates generally to devices, systems, and methods forcombustion, including but not limited to devices, systems, and methodsfor generating steam for example for use in hydrocarbon production, andin particular, enhanced production of heavy hydrocarbons from subsurfacehydrocarbon formations.

Development of oil fields generally occurs in three stages. The firststage of oil field development is primary recovery. During primaryrecovery, one or more holes are drilled from the surface down into thehydrocarbon reservoir. The pressure present in the undergroundhydrocarbon reservoir forces hydrocarbons through the wellbore to thesurface. Primary recovery continues until the pressure in thehydrocarbon reservoir is insufficient to force hydrocarbons through thewellbore to the surface. Typically only 5 percent to 15 percent of theoriginal oil in the reservoir can be recovered during the primaryrecovery stage.

The second stage of oil field development is secondary recovery. Duringsecondary recovery, various techniques may be used to recoverhydrocarbons from reservoirs with depleted pressure. One technique,known as reservoir flooding, involves injecting fluids, such as water,to increase reservoir pressure in order to force hydrocarbons throughthe wellbore to the surface. An alternative technique, known as gaslift, involves injecting gases, such as carbon dioxide, to reduce theoverall density of fluid in the wellbore. The formation pressure is thensufficient to force the less-dense fluid through the wellbore.Sometimes, pumps may be used to extract oil to the surface from thehydrocarbon reservoir. Typically, only 20 percent to 40 percent of areservoir's original oil can be extracted by primary and secondaryrecovery.

The third stage of oil field development is tertiary recovery, alsoknown as enhanced oil recovery (EOR). Following secondary recovery, alarge percentage of hydrocarbons remain trapped in the reservoir. DuringEOR, various methods are used to increase the mobility of the oil inorder to increase extraction. The most common method of EOR is steaminjection. Typically, steam is produced using a steam generator at thesurface, often part of a cogeneration plant. The steam then is injectedinto the reservoir through a wellbore where it heats the oil, therebyreducing its viscosity and making it easier to extract. Currentsteam-based oil recovery methods are effective only to about 2,500 feetdue to heat and pressure losses. Surface steam production alsoundesirably generates substantial greenhouse gas emissions.

An alternative EOR method is carbon dioxide flooding, in which carbondioxide is injected into an oil reservoir where it mixes with the oil,reducing its viscosity and making it easier to extract. Carbon dioxideflooding is particularly effective in reservoirs deeper than 2,000 feetwhere carbon dioxide is in a supercritical state. Other alternative EORmethods include injecting fluids that reduce viscosity and improve flowinto the hydrocarbon reservoir. These fluids may include gases that aremiscible with oil, air, oxygen, polymer solutions, gels,surfactant-polymer formulations, alkaline-surfactant-polymerformulations, or microorganism formulations. Current methods of EORtypically allow only an additional 5 percent to 15 percent of areservoir's oil to be recovered.

The amount of hydrocarbons that are recoverable is determined by anumber of factors including the depth of the reservoir, the permeabilityof the rock, and the strength of natural drives, such gas pressure,pressure from adjacent water, or gravity. One significant factor is theviscosity of the hydrocarbons in the reservoir. The viscosity ofhydrocarbons ranges extensively from light to heavy. Lighter oilstypically result in higher extraction rates. On the other hand, heavyoil, bitumen, and methane hydrate are highly viscous or solid and almostimpossible to extract using conventional oil production methods. Heavyoil is typically classified as oil having an API gravity of about 10 toabout 20 and a viscosity greater than about 100 cP. Bitumen is asemi-solid or solid hydrocarbon substance that typically has an API ofless than about 10 and a viscosity of greater than about 10,000 cP.Methane hydrate is a solid form of methane trapped within a crystalstructure of water. Heating methane hydrate can release gaseous methanefrom its crystal lattice structure.

Heavy oil and bitumen reserves below 2,500 feet onshore and at alldepths offshore cannot be produced using current steam technology.According to a National Institute for Petroleum and Energy Research(NIPER) study, more than half of the 68 billion barrels of remainingheavy oil reserves in the United States are below 2,500 feet. ATechnical, Economic, and Legal Assessment of North American Heavy Oil,Oil Sands, and Oil Shale Resources, U.S. Department of Energy,http://fossil.energy.gov/programs/oilgas/publications/oilshale/HeavyOilLowRes.pdf.If half of the heavy oil and oil sand deposits in the United States andCanada were brought to market, they alone could satisfy the currentdemand for crude oil in both countries for more than 150 years.America's Oil Shale: A Roadmap for Federal Decision Making, U.S.Department of Energy,http://fossil.energy.gov/programs/reserves/npr/publications/oil_shale_roadmap.pdf.

Accordingly, it would be highly desirable to provide devices, systems,and methods for enhanced production of hydrocarbons from subsurfacehydrocarbon formations. It would be particularly desirable to providedevices, systems, and methods for extraction of heavy oil, bitumen,and/or methane hydrate deposits, especially at depths greater than 2,500feet.

U.S. Pat. Nos. 4,604,988 and 7,780,152 disclose efforts to solve thisproblem by providing a downhole steam generator. However, improvementsare needed to provide combustion devices that are more efficient,reliable, and/or durable in long-term continuous use.

SUMMARY

In one aspect, an apparatus for combustion steam generation is provided.In one embodiment, the device includes a combustion chamber having aninlet end and an outlet end; a manifold housing connected to the inletend and configured to introduce a fuel and an oxidizer into thecombustion chamber; an outer casing defining a coolant chamber betweenan inner surface of the outer casing and an outer surface of thecombustion chamber; and a plurality of converging coolant inlets forconducting coolant from the coolant chamber into the combustion chamberat or near the outlet end of the combustion chamber, wherein theplurality of converging coolant inlets are radially disposed around thecombustion chamber. The plurality of converging coolant inlets may beconfigured to produce a converging-diverging nozzle from the coolantconducted into the combustion chamber. The apparatus may further includean exit flame diffuser located in fluid communication with the outletend of the combustion chamber. The apparatus preferably is sized to fitwithin industry standard well casings and/or to pass through standardturn sweeps used in horizontal wells.

In another aspect, systems and methods are provided for extracting oilfrom an oil formation including a first wellbore for delivering steamand/or other hot gases to a hydrocarbon reservoir; and an advancedcombustion thermal generator device, wherein the apparatus may belocated downhole in the first wellbore. The device may be located at adepth greater than 2,500 feet in the first wellbore. The system mayinclude a second wellbore for extracting hydrocarbons from thehydrocarbon reservoir.

In a further aspect, methods are provided for producing steam. Themethods may include introducing a fuel and an oxidizer into an inlet endof a combustion chamber; combusting the fuel and the oxidizer in thecombustion chamber to produce a combustion product; flowing a water intoa coolant chamber defined between an outer casing and an outer surfaceof the combustion chamber at or near the inlet end of the combustionchamber; flowing the water from the coolant chamber, through a pluralityof converging coolant inlets radially disposed around the combustionchamber, and into the combustion chamber at or near the outlet end ofthe combustion chamber, such that the water forms a converging-divergingnozzle through which the combustion product flows, the water becomingheated by the combustion product to form steam.

In still another aspect, methods are provided for extractinghydrocarbons from a hydrocarbon formation. The methods may includedeploying an apparatus having a combustion chamber into a wellbore;introducing a fuel and an oxidizer into an inlet end of a combustionchamber; combusting the fuel and the oxidizer in the combustion chamberto produce a combustion product; flowing a water into a coolant chamberdefined between an outer casing and an outer surface of the combustionchamber at or near the inlet end of the combustion chamber; flowing thewater from the coolant chamber, through a plurality of convergingcoolant inlets radially disposed around the combustion chamber, and intothe combustion chamber at or near the outlet end of the combustionchamber, such that the water forms the throat of a converging-divergingnozzle through which the combustion product flows, the water becomingheated by the combustion product to form steam; injecting the combustionproduct and/or the steam into the hydrocarbon formation; and extractinghydrocarbons from the hydrocarbon formation. In one variation, theapparatus having the combustion chamber is deployed into a wellbore at adepth of at least 2,500 ft below the surface.

In yet another aspect, a method is provided for forming aconvergent-divergent nozzle. The method may include combusting a fueland an oxidizer in a cylindrical combustion chamber to form a combustionproduct; and injecting water into an aft end of the cylindricalcombustion chamber through a plurality of water inlets radially disposedaround the cylindrical combustion chamber. In a particular embodiment,the flow rate of the combustion product accelerates to the speed ofsound as it converges.

In still another aspect, a convergent-divergent nozzle device isprovided, which includes an elongated annular tube having a tube walldefining a flow channel; and a nozzle located at least partially withinthe elongated annular tube, the nozzle having a converging section, athroat, and a diverging section, wherein the nozzle is formed by a gasflowing through the tube and a liquid flowing through a plurality ofapertures radially disposed about and extending through the tube wall,the longitudinal axis of each aperture extending at an angle to thedirection of the flow of the gas.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a plan view, with a portion cut away, depicting one embodimentof an apparatus for combustion steam generation as described herein.

FIG. 2 is a cross sectional view of an embodiment of an apparatus forcombustion steam generation as described herein.

FIG. 3 is an exploded view of an embodiment of a combustion apparatusfor steam generation as described herein.

FIG. 4 is a perspective view of an exterior end portion of oneembodiment of a manifold housing of an apparatus for combustion steamgeneration as described herein. (Only the manifold housing is shown;other components are omitted for clarity.)

FIG. 5 is a perspective view of the opposite side of the manifoldhousing of FIG. 4.

FIG. 6 is a graph illustrating temperature, pressure, and velocitycurves across a converging-diverging nozzle according to one embodimentof the present disclosure.

FIG. 7 is a close-up, perspective view of a portion of an embodiment ofa combustion apparatus for steam generation, wherein the outer casing isomitted to reveal the exterior of the combustion chamber and theplurality of converging coolant inlets.

FIG. 8 is a perspective view of the outlet end portion of the combustionchamber according to one embodiment of an apparatus for combustion steamgeneration as described herein.

FIG. 9 is a schematic diagram illustrating a system for extracting oilfrom an oil formation according to one embodiment of the systems andmethods described herein.

FIG. 10 is a schematic diagram illustrating a system for extracting oilfrom an oil formation according to another embodiment of the systems andmethods described herein.

FIG. 11 is a graph illustrating the cost per barrel of oil producedusing steam injection at varying well depths.

FIG. 12 is a cross sectional view of an embodiment of aconvergent-divergent nozzle device as described herein.

DETAILED DESCRIPTION

The present devices, systems and methods may be understood more readilyby reference to the following detailed description of preferredembodiments of the invention, and by reference to the drawings in whichlike numerals indicate like elements throughout the separate views.

Devices, systems, and methods for producing steam are provided, whichinclude an improved design of a combustion apparatus that introducescoolant into the exit end portion of the combustion chamber to merge thecoolant with the combustions product gases in an advantageous manner, toefficiently produce a high velocity, high quality steam. The designbeneficially can cause the coolant to form a convergent-divergentnozzle, which, unlike solid nozzle subjected to continuous use, will notwear (because the water of the water-formed nozzle is being continuouslyreplaced). This is a substantial advantage in terms of durability andcommercial viability. In a preferred embodiment, the present steamgeneration devices and systems advantageously are operable continuallyor continuously over an extended period, such as several days, months,or even years.

Among other possible uses, these devices, systems, and methods areparticularly useful for enhanced extraction of hydrocarbons fromhydrocarbon reservoirs or hydrocarbon formations. The device may beplaced downhole in a well casing to produce steam at the interface of ahydrocarbon formation, thereby efficiently delivering steam, carbondioxide, and other combustion gases to the hydrocarbon formation whileminimizing surface losses. These devices, systems, and methods also areuseful to dislodge and fluidize oil in existing oil wells that areconsidered dry (uneconomical, minimally productive, or non-productive)or that is unrecoverable through any other existing technology.

These devices, systems, and methods are particularly useful forextraction of heavy oil, bitumen, and/or methane hydrate deposits. Asused herein, “heavy oil” is highly viscous oil having an API gravity ofabout 10 to about 20 and a viscosity greater than about 100 cP. As usedherein, “bitumen” is a semi-solid or solid hydrocarbon substance havingan API of less than about 10 and a viscosity of greater than about10,000 cP. The devices, systems, and methods of the present inventionhave no depth limitation and may be useful for extraction ofhydrocarbons at all depths, including at depths greater than 2,500 feet.The devices, systems, and methods may be used either onshore ofoffshore.

I. Combustion Apparatus/Steam Generator

In one embodiment, apparatus for combustion steam generation is providedthat includes: (a) a combustion chamber having an inlet end and anoutlet end; (b) a manifold housing connected to the inlet end of thecombustion chamber that is configured to introduce a fuel and anoxidizer into the combustion chamber; (c) an outer casing defining acoolant chamber between an inner surface of the outer casing and anouter surface of the combustion chamber; and (d) a plurality ofconverging coolant inlets for conducting coolant from the coolantchamber into the combustion chamber. In certain embodiments, theplurality of converging coolant inlets may be configured to produce aconverging-diverging nozzle from the coolant conducted into thecombustion chamber. Such an apparatus or device may be termed herein anadvanced combustion thermal generator (“ACTG”) device.

As shown in FIG. 1, the ACTG device 10 is generally cylindrical inshape. The ACTG device 10 includes an outer casing 11, a manifoldhousing 12, and an exit flame diffuser 13. The outer casing 11, manifoldhousing 12, and exit flame diffuser 13 are assembled and together formthe outer portion of the ACTG device 10. The manifold housing 12 may beconnected to the outer casing 11 in any suitable manner. In oneembodiment, the manifold housing 12 includes a threaded portion that isscrewed together with a threaded inner portion of the outer casing 11 toform a gas- and fluid-tight seal. The exit flame diffuser 13 also may beconnected to the outer casing 11 in any suitable manner. In theembodiment shown, the aft end of the outer casing 11 is connected to theexit flame diffuser 13 by a plurality of screws 14 radially disposedaround the aft end of the outer casing 11. The screws engage withthreaded holes in the exit flame diffuser 13 thereby creating a gas- andfluid-tight seal between the outer casing 11 and the exit flame diffuser13.

The manifold housing 12 of the ACTG device 10 is connected to a controlline 15 that connects the ACTG device 10 to the surface (above ground).The control line 15 optionally may be a coiled tubing control line madeof an armor wired steel umbilical cable. The control line 15 includes afuel line 16, an oxidizer line 17, and a coolant line 18. The fuel line16, oxidizer line 17, and coolant line 18, are connected to a fuelsource, and oxidizer source, and a coolant source, respectfully, whichmay be located at the surface. In one embodiment, the fuel line 16,oxidizer line 17, and coolant line 18 are one inch stainless steeltubes. The control line optionally may also include one or more powerand data lines. The control line optionally may also include one or morelines for lubricants or other miscellaneous needs.

The ACTG device 10 is compact and may be dimensioned for placement downhole in the wellbore of an oil well. The ACTG device 10 may be used inboth vertical and horizontal wells. The ACTG device 10 may be sized tofit industry standard well casings. Well casings are high-strength steelpipe that generally are 20- to 40-feet in length. The well casings arescrewed together to make up a casing string and are inserted into theborehole of a wellbore. Typically well casings are held into place withcement. Industry standard oil well casing include, without limitation,standard 5-inch, 6-inch, and 7-inch casings. The ACTG device 10 also maybe sufficiently compact to accommodate standard turn sweeps used inhorizontal wells, such as horizontal wells used in steam assistedgravity drainage (see FIG. 9, described below). Steam assisted gravitydrainage is an enhanced oil recovery technique in which a pair ofhorizontal wells are drilled into an oil reservoir. One of thehorizontal wells is located above the other well. Low pressure steam iscontinuously injected into the upper wellbore to heat the oil and reduceits viscosity, causing the heated oil to drain into the lower wellbore,where it is pumped to the surface.

As shown in FIG. 2, the ACTG device 10 may be deployed in a wellbore 19having a wellbore wall 20. A wellbore casing 21 lines the outside of thewellbore 19. A packer 22 is located in the annular space between theACTG device 10 and the wellbore casing 21. Packers are sealing devicesused to isolate zones inside of well casings. The packer provides anannular seal between the outer casing 11 and the wellbore casing 21 toprevent flow of steam, combustion gases, oil or other fluids up thecasing string toward the surface. The packer also holds the ACTG device10 in place in the center of the wellbore. In other embodiments of theinvention, the packer may provide an annular seal between the outercasing and a wall of a wellbore. Standard oil well packers may be usedin accordance with embodiments of the invention.

The manifold housing 12 of the ACTG device 10 is connected at one end toa fuel line 16 and an oxidizer line 17. The fuel line 16 is connected toa fuel source, which may be located at the surface. The term “fuel” asused herein means any substance or material that is consumed to produceenergy, including without limitation natural gas, hydrogen, methane,ethane, propane, butane, gasoline, diesel fuel, kerosene, fuel oil,methanol, or alcohol, or combinations thereof. In a preferredembodiment, the fuel is methane or natural gas. The oxidizer line 17 isconnected to an oxidizer source, which may be located at the surface. Inaccordance with embodiments of the invention, the oxidizer may includeany gaseous or liquid oxidizer source, including without limitation air,gaseous oxygen (GOX), liquid oxygen (LOX), O, O₃, H₂O₂, or HAN, orcombinations thereof. In a preferred embodiment, the oxidizer is GOX.

An oxidizer, such as GOX, travels through the oxidizer line 17 to apintle 23, which is attached to the manifold housing 12. The pintle 23may generally be cylindrical in shape and may fit within a cylindricalhole through the manifold housing 12. The pintle 23 may be attached tothe manifold housing in any suitable manner. In one embodiment, thepintle 23 includes a threaded portion that is screwed together with athreaded inner portion of the manifold housing 12 to form a gas- andfluid-tight seal. Oxidizer flows through the pintle 23 into an inlet endof a combustion chamber 24. The combustion chamber 24 may be cylindricalin shape. A fuel, such as methane, travels through the fuel line 16,which is connected to the manifold housing 12. The an inner surface ofthe manifold housing 12 and an outer surface of the pintle 23 define afuel passage way 25. The fuel flows from the fuel line 16 through thefuel passage way 25 into an inlet end of the combustion chamber 24. Thefuel and oxidizer may mix at or near an inlet end of the combustionchamber 24.

The components of the ACTG device 10 may be formed of any suitablematerial, examples of which include high-temperature metals and alloys,including but not limited to nickel-chromium alloys known in the art. Inone embodiment, one or more of the components are made from Hanyes™ 230™Alloy (Haynes International, Kokomo, Ind., USA).

The manifold housing 12 of the ACTG device 10 also is connected at oneend to a power line 26. The power line 26 is connected to a powersource, which may be located at the surface. In an alternativeembodiment, the invention may include an integrated power supply, suchas a battery. An embodiment of the invention optionally may also includeone or more power and/or data lines. A power or data line may compriseone or more fiber optic power or data lines. The power line 26 isconnected to an igniter system 27. The igniter system may comprise amulti-spark discharge (MSD) ignition system. The igniter system maycomprise a spark plug, oxidizer supply, and/or fuel supply. Anembodiment of the invention optionally may include a fiber optic dataline for controlling the igniter at the point of combustion. The fiberoptic data line may transfer data to a computer control program on thesurface. The ACTG device 10 may also include one or more sensors, forexample temperature and/or pressure sensors, which are known in the art.The fiber optic data line also may transfer data from such sensors to acomputer control program on the surface. When the igniter system 27 isactivated, a spark or flame passes through the ignition flame torchpathway 28. The spark or flame causes the fuel and oxidizer to ignite inthe combustion chamber 24. The combustion of the fuel and oxidizer inthe combustion chamber 24 produces a combustion product. The combustionproduct may include carbon dioxide and steam. The combustion of the fueland oxidizer in the combustion chamber 24 also produces thermal energy.

The manifold housing 12 of the ACTG device 10 also is connected at oneend to a coolant line 18. The coolant line 18 is connected to a coolantsource, which may be located at the surface. In accordance withembodiments of the invention, the coolant may include water or anothersubstance or material that has suitable coolant properties. In apreferred embodiment, the coolant is water. Coolant may be injectedthrough a series of coolant pathways 29 in the manifold housing 12. Thecoolant may pass through the series of coolant pathways 29 into acoolant chamber 30. The coolant chamber 30 is defined by an innersurface of the outer casing 11 of the ACTG device 10 and an outersurface of the combustion chamber 24.

Coolant passes through the coolant chamber 30 and thereby providescooling to the combustion chamber 24. An inner surface of the outercasing 11 and/or an outer surface of the combustion chamber 24 may havehelical grooves or rifling. Such grooves or rifling include any helicalpattern, whether raised or lowered into the surface of a wall of thecoolant chamber 30. Such helical groves may promote a helical, orspiral, flow path of coolant through the coolant chamber 30. A helical,or spiral, flow path provides more even distribution/flow of coolant inthe coolant chamber and/or may increase turbulence, thereby reducingundesirable hot spots that may otherwise have a tendency to form in thecombustion chamber 24 and/or coolant chamber 30.

A plurality of converging coolant inlets 31 are provided at or near anoutlet end of the combustion chamber 24. The converging coolant inletsare holes extending through a wall of the combustion chamber 24 thatform a flow path for conducting coolant from the coolant chamber 30 intothe combustion chamber 24. The converging coolant inlets 31 are radiallydisposed around the combustion chamber 24. Coolant flows through theconverging coolant inlets 31 into the combustion chamber 24 at or nearthe outlet end of the combustion chamber 24. The converging coolantinlets 31 are configured to produce a converging-diverging nozzle 9 fromthe coolant conducted into the combustion chamber 24.Converging-diverging nozzles are described in more detail in section IIbelow. The coolant flows through the converging coolant inlets 31 intothe combustion chamber 24 at an angle to the flow path of the combustionproduct through the combustion chamber 24. In a preferred embodiment,the angle is between about 25 and about 35 degrees to the flow path(i.e., between about 25 and about 35 degrees to the axis of thecombustion chamber 24). In another preferred embodiment, the angle isabout 30 degrees to the flow path (i.e., about 30 degrees to the axis ofthe combustion chamber 24).

The combustion product accelerates through the converging-divergingnozzle formed by the flow of coolant into the combustion chamber 24 andpasses through the outlet end of the combustion chamber 24. The outletend of the combustion chamber is connected to an exit flame diffuser 13by a plurality of screws 14 radially disposed around the aft end of theouter casing 11. The exit flame diffuser 13 is in fluid communicationwith the outlet end of the combustion chamber 24. The exit flamediffuser 13 is generally cylindrical in shape. A plurality of holes 32are provided in the walls of the exit flame diffuser 13. The combustionchamber 24 and/or exit flame diffuser 13 form a diverging section 33 ofthe converging-diverging nozzle formed by the flow of coolant throughthe converging water inlets 31. The exit flame diffuser 13 may controlflame impingement from the combustion chamber 24 to the well casing 21.The exit flame diffuser 13 also may provide cooling to the combustionchamber 24, thereby providing a homogeneous mixture to the exhaustflame. The exit flame diffuser 13 further may provide for transfer ofadditional thermal energy from the combustion product to the coolant,thereby increasing steam production. A mixture of combustion product andsteam may exit through the exit flame diffuser holes 32 and/or an outletend of the exit flame diffuser into the wellbore 19.

FIG. 3 provides another view to understand the components of the ACTGdevice 10. Specifically, FIG. 3 shows a pintle 23, a manifold housing12, a combustion chamber 24, an outer casing 11, and an exit flamediffuser 13. The ACTG device 10 may exist as an assembly, as shown inFIGS. 1-2. The ACTG device 10 is assembled by connecting the pintle 23within the manifold housing 12, for example by screwing an outerthreaded portion of the pintle 23 into an inner threaded portion of themanifold housing 12. The manifold housing 12 is connected to thecombustion chamber 24, for example by screwing an inner threaded portionof the combustion chamber 24 to a threaded outer portion of the manifoldhousing 12. The surface of the combustion chamber 24 has helical grooves39 in accordance with a preferred embodiment. Alternatively oradditionally, an inner surface of the outer casing 11 may have helicalgrooves in accordance with a preferred embodiment of the invention. Theouter casing 11 fits over the combustion chamber 24 and connects to themanifold housing 12, for example by screwing an inner threaded portionof the outer casing 11 to a threaded outer portion of the manifoldhousing 12. When assembled, the annular space between the outer casing11 and the combustion chamber 24 defines a coolant chamber (not shown).The exit flame diffuser 13 connects to the outer casing by a pluralityof screws 14 radially disposed around the aft end of the outer casing11. The screws engage with threaded holes 34 in the exit flame diffuser13 thereby creating a gas- and fluid-tight seal between the outer casing11 and the exit flame diffuser 13. When assembled, the exit flamediffuser 13 is in fluid communication with the combustion chamber 24.

Details of one embodiment of the manifold housing 12 are shown in FIGS.4 and 5. The manifold housing 12 includes a fuel inlet 35, an oxidizerinlet 36, a coolant inlet 37, and a power and data systems inlet 38. Thefuel inlet 35 may be connected to a fuel line. The fuel line may, inturn, be connected to a fuel source, which may be located at the surfaceof the well. The oxidizer inlet 36 may be connected to an oxidizer line.The oxidizer line may, in turn, be connected to an oxidizer source,which may be located at the surface. The coolant inlet 37 may beconnected to a coolant line. The coolant line may, in turn, be connectedto a coolant source, which may be located at the surface. The power anddata systems inlet 38 may be connected to power and/or data lines. Thepower and/or data lines may, in turn, be connected to a power source,computer, and/or control systems, which may be located at the surface.It is envisioned that the number and/or placement of any of these inletsmay be varied.

As shown in FIG. 5, the manifold housing 12 is connected with a pintle23. Oxidizer flows from an oxidizer line through the pintle 23 into thecombustion chamber. The manifold housing 12 and pintle 23 together forma fuel passageway 25 through which fuel flows from a fuel line into thecombustion chamber. Coolant flows from a coolant line through a seriesof coolant pathways 29 in the manifold housing 12 into a coolant chamberformed by the outer casing and the combustion chamber. The manifoldhousing 12 also includes an ignition flame torch pathway 28. An ignitersystem may be located within the manifold housing 12. When the ignitersystem is activated, a spark or flame may pass through the ignitionflame torch pathway 28 and may cause fuel and oxidizer to ignite in thecombustion chamber.

II. Converging-Diverging Nozzle

The ACTG device may be configured so as to produce aconverging-diverging nozzle from the coolant conducted into thecombustion chamber. A converging-diverging nozzle, also known as a deLaval (or DeLaval) nozzle, is a device that accelerates a hightemperature, high pressure gas to a supersonic speed. Typically, it is atube that is pinched in the middle to form a balanced, asymmetrichourglass-shape. An exemplary converging-diverging nozzle is shown anddescribed in U.S. Pat. No. 4,064,977, which is incorporated herein byreference in its entirety.

Generally a converging-diverging nozzle includes a converging section, athroat, and a diverging section. Typically it is made of steel, copper,graphite, or another type of ablative material that is susceptible towear over time.

A convergent-divergent nozzle operates by forcing a constant mass flowrate of gas through an orifice with a small cross-section. From thepoint of view of the gas in the converging section, the nozzle is ahole, or “throat,” that leads to a lower pressure area. As the gasapproaches the throat, it begins to accelerate. The gas continues toaccelerate toward the throat, ultimately reaching the speed of sound atthe throat. The “speed of sound” as used herein is the speed of sound inthe hot gas, not the speed of sound in air at ground level in ambientconditions. The speed of sound in hot gas typically is 2 to 3 timesfaster than the speed of sound in air at ground level in ambientconditions, depending on temperature.

After the gas reaches sonic speed at the throat, it flows into thediverging section, where the gas expands and cools, pushes sideways atan oblique angle to the wall, and accelerates to supersonic speeds. Abell-shaped divergent section of the nozzle provides maximum efficiency,but a simple cone-shaped divergent section provides 99 percentefficiency and can provide more cost-effective construction. Thedivergent section of the nozzle can increase the speed of the gas by 2.7times the speed of sound or more, depending on the exact ratio of thecross-sectional area at the throat to the cross-sectional area at theexit from the nozzle.

The nozzle functions to convert the potential energy of the hightemperature, high pressure gas into kinetic energy. Because of the hightemperature and high velocity of gases passing through the throat of atypical converging-diverging nozzle, the throat of the nozzle may erode,resulting in undesirable increases in throat diameter and decreases inchamber pressure and gas velocity. The erosion in the nozzle throatultimately limits the life of the nozzle and the run time of the deviceincorporating the nozzle.

Advantageously, the advanced combustion thermal generators describedherein utilize converging-diverging nozzles formed by the flow ofcoolant, which preferably is water, instead of by mechanical means suchas a metal throat. Accordingly, the device may operate for yearsunderground without needing to replace components, such as the nozzle,of the device.

In one aspect, a method is provided for forming a convergent-divergentnozzle by combusting a fuel and an oxidizer in a cylindrical combustionchamber to form a combustion product and by injecting water into an aftend of the cylindrical combustion chamber through a plurality ofconverging water inlets radially disposed around the cylindricalcombustion chamber. The water is injected into the combustion chamber atan angle (e shown in FIG. 12) to the axis of the cylindrical combustionchamber in a manner effective to cause the combustion product toconverge by decreasing the effective cross-sectional area of thecombustion chamber. The water being pushed through the combustionchamber eventually reaches a density such that the gas can compress nofurther, and the water thereby establishes the throat of the de Lavalnozzle. In a preferred embodiment, the water may be injected at an anglebetween about 25 degrees and about 35 degrees to the axis of thecylindrical combustion chamber. In another preferred embodiment, thewater may be injected at an angle of about 30 degrees to the axis of thecombustion chamber. In another preferred embodiment, the flow rate ofthe combustion product accelerates to the speed of sound as itconverges.

FIG. 6 is a graph illustrating temperature, pressure, and velocitycurves across a converging-diverging nozzle in accordance with anembodiment of the devices and systems described herein. As thecombustion product flows through the combustion chamber it nears theoutlet end of the combustion chamber and enters the converging sectionof the nozzle. As it converges, the combustion product accelerates andthe temperature and pressure begin to decrease. At the throat, which isformed by the flow of water into the combustion chamber, the velocityincreases significantly to sonic speeds and the temperature and pressureof the gases drop accordingly. As the combustion product exits thethroat and enters the diverging section of the combustion chamber and/orexit flame diffuser the velocity increases to supersonic speeds and thepressure and temperature drop further.

It will therefore be appreciated that the coolant may serve at least twopurposes in the device. First, the coolant provides cooling of thecombustion chamber as it flows through the coolant chamber. Second, theinjection of coolant into the combustion chamber at an angle to the axisof the combustion chamber may create a converging-diverging nozzle toaccelerate the velocity of the combustion product and steam dischargedfrom the ACTG. It also will be appreciated that the flow rate ofcoolant, fuel, and/or oxidizer may be variable and adjustable so that asthe pressure of hydrocarbons in the hydrocarbon formation changes, theflow rate of coolant may change accordingly to compensate for thosechanges. Thus, the flow rate of coolant, fuel, and/or oxidizer may beadjusted so as to provide an injectable flow rate of gases into theformation and optimal performance of embodiments of the device. It alsowill be appreciated that the flow of combustion product and coolantcauses minimal or no erosion to surfaces of embodiments of the device.

The water injected into the cylindrical chamber through the convergingwater inlets may exit into the exit flame diffuser and mix with thecombustion product. There, the water may convert to steam and exit theACTG device into the wellbore or hydrocarbon formation.

The outlet end of the combustion chamber 24 is detailed in FIGS. 7 and8. As shown in FIG. 7, an outlet end of a combustion chamber 24 isconnected to an exit flame diffuser 13. The outer casing that ordinarilywould enclose the combustion chamber 24 and define a coolant chamber isnot shown for purposes of clarity of the underlying structures. Aplurality of converging coolant inlets 31 are radially disposed aroundthe combustion chamber 24. The plurality of converging coolant inlets 31extend through the wall of the combustion chamber 24 at an angle to thedirection of flow of combustion product through the combustion chamber24. The converging coolant inlets are configured to produce aconverging-diverging nozzle from the coolant conducted into thecombustion chamber. In a preferred embodiment, the angle of theconverging coolant inlets is between about 25 degrees and about 35degrees. In another preferred embodiment, the angle of the convergingcoolant inlets is about 30 degrees.

In FIG. 8, the exit flame diffuser that ordinarily would connect to theoutlet end of the combustion chamber is omitted to show the internalwall at the outlet end of the combustion chamber 24. The convergingcoolant inlets 31 are configured to produce a converging-divergingnozzle from the coolant injected into the combustion chamber 24. Inorder to form a converging-diverging nozzle, water (coolant) is injectedthrough the converging water inlets 31 at an angle to the axis of thecylindrical combustion chamber 24. Flowing combustion product pushes thewater through the out end of combustion chamber 24. The water reducesthe effective cross-sectional area of the combustion chamber 24 andestablishes the throat of a converging-diverging nozzle. In a preferredembodiment, the flow rate of the combustion product accelerates to thespeed of sound as it converges. As the combustion product exits thethroat, it enters a diverging section 33 of the combustion chamberand/or exit flame diffuser. In the diverging section 33, the internaldiameter of the flow path increases and the velocity of the gases mayincrease to supersonic speeds.

III. Systems and Methods for Enhanced Oil Recovery

Systems and methods of producing steam and extracting hydrocarbons fromhydrocarbon reservoirs or hydrocarbon formations are provided inaccordance with certain embodiments described herein. These systemsinclude the ACTG devices described herein deployed downhole to producesteam and carbon dioxide for enhanced recovery of oil or otherhydrocarbons.

The ACTG devices may be used to reduce or eliminate surface steam lossesthat occur in traditional steam injection enhanced oil recovery systemsand methods. Advantageously, ACTG devices may deliver steam directly toa reservoir interface. Such embodiments may be particularly useful forreservoirs at depths over 2,500 feet and/or reservoirs that compriseheavy oil or bitumen. Such embodiments also be used in offshore ornear-offshore reservoirs and to extract heavy oil or bitumen underpermafrost conditions. The steam quality produced by ACTG devices may becontrolled as needed. For example, embodiments may produce steamqualities of between about 10 percent and about 95 percent or more. Inone embodiment, the steam quality produced is from about 75 percent toabout 95 percent, such as from about 85 percent and about 95 percent. Inpreferred embodiments, the ACTG device produces steam at a steam qualitybetween 90 percent and 100 percent, available to the hydrocarbonformation.

Systems are provided for extracting hydrocarbons from a hydrocarbonformation. Systems for enhanced oil recovery include a first wellborefor delivering steam and/or other hot gases to a hydrocarbon reservoirand an advanced combustion thermal generator device of an embodiment ofthe present invention (see descriptions in sections I and II above). TheACTG device may be located downhole in the first wellbore. The steamand/or other hot gases may provide heat to the hydrocarbons in theformation to reduce the viscosity and/or vaporize part of thehydrocarbons. In a preferred embodiment, the hydrocarbon reservoir mayinclude heavy oil, bitumen, methane hydrate, or a combination thereof.

The systems for enhanced oil recovery optionally may further include asecond wellbore for extracting hydrocarbons from a hydrocarbonreservoir. Either one or both of the first and second wellbores may bevertical wellbores in accordance with various embodiments of thepresently disclosed devices, systems, and methods. Alternatively, eitherone or both of the first and second wellbores may include at least onehorizontal section. An ACTG device may be located at any point in thewellbore including in a vertical section or a horizontal section of thewellbore. An ACTG device also may be located at any depth in thewellbore. The ACTG device is particularly advantageous in uses where theACTG device is deployed to a depth below the surface of greater than2,500 feet.

The systems for enhanced oil recovery optionally may further include acasing string extending from about the top of the first wellbore toabout the bottom of the first wellbore. In a preferred embodiment, anACTG device may be located within the casing string.

The systems for enhanced oil recovery may further include a fuel source,an oxidizer source, and/or a coolant source. The fuel source, oxidizersource, and/or coolant source may be connected to an ACTG device by acoiled tubing control line. The coiled tubing control line optionallymay include a fuel feed line, and oxidizer feed line, and/or a coolantfeed line. The coiled tubing control line optionally may also include afiber optic data line and/or a power line.

As shown in FIG. 9, a steam-assisted gravity drainage system utilizingan ACTG device as described herein may be used. The system includes afirst wellbore 50 for delivering steam and/or other hot gases to ahydrocarbon reservoir 51 (the “Steam Injection Wellbore”). In apreferred embodiment, the hydrocarbon reservoir includes heavy oil,bitumen, and/or methane hydrate. The system also includes a secondwellbore 52 for extracting hydrocarbons from the hydrocarbon reservoir51 (the “Production Wellbore”). An ACTG device 10 is located downhole inthe casing string of the first wellbore 50. The ACTG device is connectedto water, fuel, and oxidizer sources at the surface via a control line58 that includes a water feed line 59, a fuel feed line 60, and anoxidizer feed line 61. In alternative embodiments, the control line mayfurther comprise a fiber optic data line and/or a power line.

The first wellbore includes a vertical section 53 and a horizontalsection 54. The ACTG device 10 is sized to fit within the wellbore 50and sized to pass through the turn sweep 55 used in the horizontalwellbore. The second wellbore also includes a vertical section 56 and ahorizontal section 57. The horizontal section of the second wellbore islocated under the horizontal section of the first wellbore.

The ACTG device 10 may generate steam and combustion gas by methodsdescribed herein. For example, the ACTG device 10 may generate steam andcombustion gas by introducing a fuel and an oxidizer into an inlet endof a combustion chamber, combusting the fuel and the oxidizer in thecombustion chamber to produce a combustion product, flowing water into acoolant chamber defined between an outer casing and an outer surface ofthe combustion chamber at or near the inlet end of the combustionchamber, and flowing the water from the coolant chamber, through aplurality of converging coolant inlets radially disposed around thecombustion chamber, and into the combustion chamber at or near theoutlet end of the combustion chamber, such that the water forms aconverging-diverging nozzle through which the combustion product flows,the water becoming heated by the combustion product to form steam. In apreferred embodiment, the fuel, the oxidizer, and the water may bemetered to produce steam at a pressure from about 120 psig to about2,950 psig. In another preferred embodiment, the fuel, the oxidizer, andthe water may be metered to produce steam at a steam quality of fromabout 75 percent to about 99 percent, such as from about 85 percent toabout 95 percent.

The steam and combustion gas may be injected into the wellbore 50 and/orinto the hydrocarbon formation 51 by the ACTG device 10. In a preferredembodiment, the ACTG device 10 is deployed at a depth greater than 2,500feet and the steam and combustion gas is injected into the well bore 50and/or into the hydrocarbon formation 51 at a depth greater than 2,500feet. In a preferred embodiment, the steam is injected into thehydrocarbon formation 51 at a pressure from about 120 psig to about2,950 psig. In another preferred embodiment, the steam is injected intothe hydrocarbon formation 51 at a steam quality of between about 75percent and about 95 percent. In another preferred embodiment, thecombustion product comprises at least 50 percent carbon dioxide. Inanother preferred embodiment, the carbon dioxide is a supercriticalfluid. In another preferred embodiment, the carbon dioxide is injectedinto the hydrocarbon formation in an amount effective to decrease theviscosity of the hydrocarbons in the hydrocarbon formation 51. Inanother embodiment, the carbon dioxide swells the oil and/or increasesoil flow drive.

The injection of steam and combustion gas (including carbon dioxide)into the hydrocarbon reservoir 51 causes a decrease in the viscosity ofthe hydrocarbons in the reservoir 51. The less viscous hydrocarbons flowdown to the horizontal portion 57 of the second wellbore 52. Aproduction facility 62 at the surface of the second wellbore 52 extractshydrocarbons from the hydrocarbon formation.

FIG. 10 shows a steam flooding system utilizing an ACTG device asdescribed herein. The system includes a first wellbore 63 for deliveringsteam and/or other hot gases to a hydrocarbon reservoir 64. In apreferred embodiment, the hydrocarbon reservoir includes heavy oil,bitumen, and/or methane hydrate. The system also includes a secondwellbore 65 for extracting hydrocarbons from the hydrocarbon reservoir64. Both the first wellbore 63 and the second wellbore 65 are verticalwellbores.

An ACTG device (not shown) is located downhole in the casing string ofthe first wellbore 63. In a preferred embodiment, the ACTG device islocated at a depth at or greater than 2,500 feet. The steam andcombustion product produced by ACTG device is injected into thehydrocarbon reservoir 64. In this embodiment, the steam and hot gasesform a steam front, which heats the hydrocarbons, lowers the viscosityof the hydrocarbons, and pushes the hydrocarbons towards the productionwellbore 65. A production facility 66 at the surface of the productionwellbore 65 extracts hydrocarbons from the hydrocarbon formation.

Unlike traditional steam-based enhanced oil recovery techniques, thepresent devices and systems are not limited by depth. Accordingly, thedevices, systems, and methods may reduce the cost of oil production,particularly at depths below about 1,500 feet. FIG. 11 is a graphillustrating the cost per barrel of oil produced using steam injectionat varying well depths. Curves a, b, and c depict the cost per barrel ofoil recovered using surface steam at various steam qualities. Curve adepicts the cost per barrel of oil recovered using surface steam at 40percent quality and a 0.92 kg/sec rate of injection. Curve b depicts thecost per barrel of oil recovered using surface steam at 80 percentquality and a 0.92 kg/sec rate of injection. Curve c depicts the costper barrel of oil recovered using surface steam at 80 percent qualityand a 2.75 kg/sec rate of injection.

Curve d depicts the cost per barrel of oil recovered using an embodimentof the systems and devices described herein. Unlike surface steam, thecost per barrel of oil recovered using the present devices and systemsdoes not vary appreciably with well depth. Thus, these devices, systems,and methods offer cost advantages over traditional enhanced oil recoverymethods, particularly for deep and/or heavy deposits.

FIG. 12 shows the flow of coolant to form a converging-diverging nozzlein an ACTG device 10. As described in section I above, the ACTG device10 includes a combustion chamber 24 and an outer casing 11 that define acoolant chamber 30. In operation, coolant fills the coolant chamber 30.A plurality of converging coolant inlets 31 are radially disposed aroundthe combustion chamber 24. Coolant flows from the coolant chamber 30through the converging coolant inlets 31 into the combustion chamber 24at or near the outlet end of the combustion chamber 24. The convergingcoolant inlets 31 are configured to produce a converging-divergingnozzle 9 from the coolant conducted into the combustion chamber 24.Converging-diverging nozzles are described in more detail in section IIabove. After flowing into the combustion chamber 24, the coolantinitially converges toward the axial centerline of the combustionchamber 24 but is forced outward to the wall of the combustion chamberby the force of the flowing combustion product. The coolant, being anincompressible fluid, forms a layer of water concentric with thecombustion chamber wall. This concentric layer of water serves as athroat though which the combustion product must flow. Combustion productfrom the combustion chamber may accelerate through the convergingsection and the throat to sonic or supersonic velocities. After thethroat, the combustion product and coolant flow to a diverging section33 and an exit flame diffuser 13. A plurality of holes 32 are providedin the walls of the exit flame diffuser 13. In the diverging section 33and the exit flame diffuser 13 the combustion product may continue toaccelerate to supersonic velocities. In one embodiment, the coolant iswater and is heated by the combustion product in the diverging section33 and/or the exit flame diffuser 13. In another embodiment, thediverging section 33 is integral with or forms a part of the exit flamediffuser 13. The conversion of water to steam is depicted by the shadingin FIG. 12. A mixture of combustion product and steam may exit the ACTGdevice 10 and be injected into a wellbore and/or a hydrocarbonformation.

Devices and systems for enhanced oil recovery may optionally includeother standard well production equipment; packer(s); a controller systemfor measuring the process conditions (e.g., temperature, pressure) andadjusting pressures and flow rates of fluids to an ACTG device.Advantageously, the device or system may be controlled to manageproduction from the reservoir. For example, the flow of oxidizer, fuel,and coolant may be regulated to provide the desired amount of steam andpressure (e.g., steam may be provided from 120 psig to 2950 psig).

The presently disclosed devices, systems, and methods may also be usedin a larger scale surface steam configuration for shallow wells, tarsands and shale. Thermal conversion efficiencies of fuel-to-steam inexcess of 99 percent, nearly penalty free compression, and 50 percentratio of pure carbon dioxide as a byproduct of combustion may beachieved by such a model.

Devices and systems for enhanced oil recovery of the present inventionalso optionally may deliver downhole chemical payloads to the formationas needed. For example, applications may include flame front control,oxidizer delivery for in situ combustion, and underground coalgasification. Such modification and adaptations are within the skill ofone of ordinary skill in the art and are intended to come within thescope of the appended claims

Publications cited herein and the materials for which they are cited arespecifically incorporated by reference in their entirety withoutadmission that such is prior art. Modifications and variations of thedevices, systems, and devices described herein will be obvious to thoseskilled in the art from the foregoing detailed description. Suchmodifications and variations are intended to come within the scope ofthe appended claims.

I claim:
 1. A method for reducing the viscosity and/or vaporizinghydrocarbons in an underground hydrocarbon reservoir, the methodcomprising: generating steam downhole within a wellbore; acceleratingthe steam to a supersonic speed within the wellbore using aconvergent-divergent nozzle; and injecting the accelerated steam into ahydrocarbon formation.
 2. The method of claim 1, wherein the hydrocarbonformation comprises heavy oil, bitumen, methane hydrate, or acombination thereof.
 3. The method of claim 1, wherein the acceleratedsteam has a steam quality between 90% and 100%.
 4. The method of claim1, wherein accelerated steam further includes carbon dioxide gas mixedtherein.
 5. The method of claim 1, wherein the steam is generated at adepth greater than 2500 feet underground.
 6. The method of claim 1,wherein the convergent portion of the nozzle is formed of flowing water.7. A method for reducing the viscosity and/or vaporizing hydrocarbons inan underground hydrocarbon reservoir, the method comprising: using acombustion apparatus placed downhole within a wellbore to generatesteam; accelerating the steam to a supersonic speed within the wellboreusing a convergent-divergent nozzle; and injecting the accelerated steaminto a hydrocarbon formation which comprises heavy oil, bitumen, methanehydrate, or a combination thereof.
 8. The method of claim 7, wherein theaccelerated steam has a steam quality between 90% and 100%.
 9. Themethod of claim 7, wherein accelerated steam further includes carbondioxide gas mixed therein.
 10. The method of claim 7, wherein the steamis generated at a depth greater than 2500 feet underground.
 11. Themethod of claim 7, wherein the convergent portion of the nozzle isformed of flowing water.
 12. The method of claim 7, wherein thecombustion apparatus is an advanced combustion thermal generator (ACTG).